Method and composition for enhancing coverage and displacement of treatment fluids into subterranean formations

ABSTRACT

A method of injecting a treatment fluid into a portion of a subterranean formation, comprising providing a treatment fluid having a viscosity; determining the breakdown pressure of the portion of the subterranean formation; calculating the maximum sustainable flow rate for the treatment fluid; and, injecting the treatment fluid into the portion of the subterranean formation at a flow rate less than or equal to the maximum sustainable flow rate for the treatment fluid. A method of injecting a treatment fluid into a portion of a subterranean formation, comprising providing a treatment fluid having a viscosity; determining the breakdown pressure of the portion of the subterranean formation; calculating the maximum allowable treatment fluid viscosity; adjusting the viscosity of the treatment fluid to a viscosity less than or equal to the maximum allowable treatment fluid viscosity; and injecting the treatment fluid into the subterranean formation at the selected treatment fluid flow rate.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation of U.S. patent application Ser. No.10/961,508, filed Oct. 8, 2004 now U.S. Pat. No. 7,757,768, which isherein incorporated by reference in its entirety.

BACKGROUND

The present invention relates to chemical treatments for oil and gaswells. More particularly, the present invention relates to methods andcompositions for enhancing the coverage and displacement of treatmentfluids into subterranean formations.

Chemical treatments for oil and gas wells often involve sequentialinjections of one or more fluids, such as a preflush, chemical agent,spacer, and/or afterflush. Typically treatment fluids are injected intoa subterranean formation at the matrix flow rate, i.e., the rate atwhich the treatment fluid enters laminar flow inside the formation. Atthis rate the treatment fluid enters the interstitial spaces of theformation at a flow rate low enough to avoid generating areas of highpressure within the formation that could cause the formation to fractureinadvertently. The success of these treatments often relies on theeffective coverage and displacement of one fluid by another.Unfortunately, problems of uneven distribution or placement of treatmentfluids are often encountered in well bores containing multiple layerswith highly variable permeabilities.

Previously, acid stimulation treatments have applied Paccaloni's maximumpressure differential and injection rate (“MAPDIR”) method, which usesthe injection rate as the key parameter to obtain a desired bottomholepressure differential. However, Paccaloni's MAPDIR method and othermethods involving high injection rates have not been widely adoptedoutside of acid stimulation treatments. This is due to the fact thatmany other treatment fluids, such as curable resins, are too viscous tobe pumped into a formation at a flow rate sufficiently high enough tomaximize the pressure differential without fear of inadvertentlyfracturing the formation. Furthermore, traditional solvents that couldbe used to lower the viscosity of the treatment fluids also tend torender the fluids less capable of adequately coating the formation,sometimes defeating the purpose of injecting the fluids into theformation.

SUMMARY

The present invention relates to chemical treatments for oil and gaswells. More particularly, the present invention relates to methods andcompositions for enhancing the coverage and displacement of treatmentfluids into subterranean formations.

A method of injecting a treatment fluid into a portion of a subterraneanformation, comprising providing a treatment fluid having a viscosity;determining the breakdown pressure of the portion of the subterraneanformation; calculating the maximum sustainable flow rate for thetreatment fluid; and, injecting the treatment fluid into the portion ofthe subterranean formation at a flow rate less than or equal to themaximum sustainable flow rate for the treatment fluid.

A method of injecting a treatment fluid into a portion of a subterraneanformation, comprising providing a treatment fluid having a viscosity;determining the breakdown pressure of the portion of the subterraneanformation; calculating the maximum allowable treatment fluid viscosity;adjusting the viscosity of the treatment fluid to a viscosity less thanor equal to the maximum allowable treatment fluid viscosity; andinjecting the treatment fluid into the subterranean formation at theselected treatment fluid flow rate.

The features and advantages of the present invention will be readilyapparent to those skilled in the art upon a reading of the descriptionof the preferred embodiments that follows.

DESCRIPTION OF THE PREFERRED EMBODIMENTS

The present invention relates to chemical treatments for oil and gaswells. More particularly, the present invention relates to methods andcompositions for enhancing the coverage and displacement of treatmentfluids into subterranean formations.

In accordance with the present invention, a treatment fluid may beinjected into a subterranean formation at a combination of a flow rateand a viscosity selected to maximize down hole pressure and yet remainbelow the “breakdown pressure.” The term “breakdown pressure,” as usedherein, refers to a pressure at which the treating pressure exceeds thestrength of the rock and the formation fractures. By injecting thetreatment fluid at such a maximum down hole pressure, the method of thepresent invention allows for the enhanced coverage and displacement ofthe treatment fluid into the formation, often without the need for adiverting agent. In the methods of the present invention, the flow rateis generally selected by calculating the maximum sustainable flow ratethat will not result in the fracturing of the formation, given thechosen viscosity of the treatment fluid. This flow rate may be thoughtof as the maximum rate condition that can be achieved while stayingbelow the fracture gradient. In particular embodiments, the viscosity ofthe treatment fluid may also be adjusted in addition to, or in place of,adjusting the flow rate, to maximize the down hole pressure.

The ability to inject treatment fluids into a subterranean formation ator near the breakdown pressure of the formation may offer numerousbenefits. In particular embodiments of the present invention, maximizingthe down hole pressure by controlling the flow rate and/or the viscosityof the treatment fluid may allow the coverage of the treatment fluid tobe extended into the subterranean formation, despite the presence ofportions of the subterranean formation to be treated having areas ofvarying permeabilities along the length of the well bore. By maximizingthe well bore pressure down hole without fracturing the formation, thehighest possible pressure difference is created between the reservoirand the well bore, helping to force the treatment fluid to enter lowerpermeability regions of the formation that it might not have reachedotherwise. Furthermore, in particular embodiments of the presentinvention, the coverage of a fluid in the formation and/or itsdisplacement efficiency may be enhanced by adjusting the injection rateand/or viscosity of a later-introduced treatment fluid. Because eachfluid in the treatment has its own viscosity, the injection rate of eachfluid may be adjusted such that the maximum allowable injection pressurefor each fluid is maintained while that fluid is being injected downhole without fracturing the formation. Thus, using tailored flow ratesand tailored viscosities combined with MAPDIR pumping procedures, longerintervals of the well bore may be treated more effectively.

A variety of treatment fluids may be injected into a subterraneanformation in accordance with teachings of the present invention. In someembodiments, the treatment fluid may comprise a curable resin. Otherembodiments of the present invention may use a treatment fluidcomprising a water controlling agent.

Resins suitable for use as treatment fluids in the present inventioninclude all resins known in the art that are capable of forming ahardened, consolidated mass. Many such resins are commonly used insubterranean consolidation operations, and some suitable resins includetwo component epoxy based resins, novolak resins, polyepoxide resins,phenol-aldehyde resins, urea-aldehyde resins, urethane resins, phenolicresins, furan resins, furan/furfuryl alcohol resins, phenolic/latexresins, phenol formaldehyde resins, polyester resins and hybrids andcopolymers thereof, polyurethane resins and hybrids and copolymersthereof, acrylate resins, and mixtures thereof. Some suitable resins,such as epoxy resins, may be cured with an internal catalyst oractivator so that when pumped down hole, they may be cured using onlytime and temperature. Other suitable resins, such as furan resinsgenerally require a time-delayed catalyst or an external catalyst tohelp activate the polymerization of the resins if the cure temperatureis low (i.e., less than 250° F.), but will cure under the effect of timeand temperature if the formation temperature is above about 250° F.,preferably above about 300° F. It is within the ability of one skilledin the art, with the benefit of this disclosure, to select a suitableresin for use in embodiments of the present invention and to determinewhether a catalyst is required to trigger curing.

Selection of a suitable resin may be affected by the temperature of thesubterranean formation to which the fluid will be introduced. By way ofexample, for subterranean formations having a bottom hole statictemperature (“BHST”) ranging from about 60° F. to about 250° F.,two-component epoxy-based resins comprising a hardenable resin componentand a hardening agent component containing specific hardening agents maybe preferred. For subterranean formations having a BHST ranging fromabout 300° F. to about 600° F., a furan-based resin may be preferred.For subterranean formations having a BHST ranging from about 200° F. toabout 400° F., either a phenolic-based resin or a one-component HTepoxy-based resin may be suitable. For subterranean formations having aBHST of at least about 175° F., a phenol/phenol formaldehyde/furfurylalcohol resin may also be suitable.

Water controlling agents may also be suitable treatment fluids in thepresent invention. A variety of agents have been used to reduce thewater permeability of subterranean formations, such as surfactantsformed of one or more fatty acid imidazolyl compounds andwater-resistant polymers. Water-resistant polymers, also known asrelative permeability modifiers, act, inter alia, to adsorb onto thesurfaces within the pores of a formation to reduce the formation's waterpermeability. A variety of water-resistant polymers are suitable for useas water controlling agents in the present invention. Examples ofparticularly suitable polymers include, but are not limited to,polyacrylamide, hydrolyzed polyacrylamide, xanthan, scleroglucan,polysaccharides, amphoteric polymers made from acrylamide, acrylic acid,diallyldimethylammonium chloride, vinyl sulfonate/vinyl amide/acrylamideterpolymers, vinyl sulfonate/acrylamide copolymers,acrylamide/acrylamido-methylpropanesulfonic acid copolymers,acrylamide/vinylpyrrolidone copolymers, sodium carboxymethyl cellulose,poly [dialkylaminoacrylate-co-acrylate-g-poly(ethyleneoxide)],acrylamide/octadecyldimethylammoniumethyl methacrylate bromidecopolymer, dimethylaminoethyl methacrylate/vinylpyrrolidone/hexadecyldimethylammoniummethyl methacrylate bromideterpolymer, acrylamide/2-acrylamido-2-methyl propane sulfonicacid/2-ethylhexyl methacrylate terpolymer, and combinations thereof. Asused herein “-g-” in a formula means that the immediately followingmolecule in the formula is grafted to the preceding polymer molecule.

Regardless of the chosen treatment fluid, before it is injecting intothe subterranean formation, the breakdown pressure of the subterraneanformation must first be determined. The breakdown pressure of thesubterranean formation may be determined using a variety of techniqueswell-known in the art. Examples of such techniques include, but are notlimited to, the analysis of Step Rate Injection Tests, Full Wave Sonicor Dipole Sonic logging tools for mechanical rock properties and stress,the analysis of borehole breakouts during drilling, and minifracanalysis. During treating the near well bore, it is preferable that thetreating bottom hole pressure is maintained below that of the breakdownpressure. Because once the fractures are generated, the treatment fluidswill tend to flow or leak off into the fractures, defeating the purposeof treating the near well bore area. With the benefit of thisdisclosure, it should be within the ability of one skilled in the art toselect an appropriate method of determine the reservoir stress orfracture gradient.

Having determined the breakdown pressure of the subterranean formation,particular embodiments of the present invention manipulate the flow rateof the treatment fluid to maintain a down hole pressure less than thebreakdown pressure of the formation. This flow rate may be calculated bydetermining the maximum sustainable flow rate that will not result inthe fracturing of the formation, given the breakdown pressure of theformation and the viscosity of the treatment fluid to be injected intothe formation. Assuming pseudo-steady-state flow, the maximumnon-fracturing injection flow rate q_(i,max) is related to the breakdownpressure, p_(bd), by the following equation:

$q_{{i,{m\;{ax}}}\;} = \frac{\left( {p_{bd} - p_{e}} \right){kh}}{141.2\mspace{14mu}{\mu\left\lbrack {{\ln\left( \frac{r_{b}}{r_{w}} \right)} + s} \right\rbrack}}$where p_(e) is the average reservoir pressure, k is the permeability ofthe formation, h is the net pay, μ is the viscosity of the fluid, r_(b)is the radius of the formation cylinder in which the majority of thepressure drop takes place, r_(w) is the well bore radius, and s is theskin factor for the well bore. Additional information on therelationship between injection flow rates, fluid viscosities, andbreakdown pressures may be found in MICHAEL J. ECONOMIDES, A DANIEL HILL& CHRISTINE EHLIG-ECONOMIDES, PETROLEUM PRODUCTION SYSTEMS CH. 14(Prentice Hall Petroleum Engineering Series 1994) and G. PACCALONI, M.TAMBINI & M. GALOPPINO, KEY FACTORS FOR ENHANCED RESULTS OF MATRIXSTIMULATION TREATMENTS, SPE 17154 (1988), the relevant disclosures ofwhich are hereby incorporated by reference. In particular embodiments,the selected flow rate may be adjusted downwards from the maximumnon-fracturing flow rate as an additional measure to further ensure theformation does not fracture inadvertently. In particular embodiments ofthe present invention, the selected flow rate may be range from about80% to about 90% of the maximum non-fracturing flow rate. Additionally,the flow rate is typically monitored in real time to ensure that thedesired flow rate is being achieved, as well as to determine when asufficient amount of the treatment chemical has been injected into theformation.

In addition to, or in place of, manipulating the flow rate of thetreatment fluid, particular embodiments of the present invention maymanipulate the viscosity of the treatment fluid to maximize the bottomhole pressure of the well bore. Such viscosity manipulation may beparticularly useful in cases wherein the treatment fluid is curableresin. By lowering the viscosity of curable resin it may possible toinject the resin into the subterranean formation at a higher flow rate.In particular embodiments of the present invention, this reduction inthe viscosity of the curable resin may be accomplished by adding asolvent or dispersant to the treatment fluid. Examples of suitablesolvents include, but are not limited to, methanol, isopropanol,butanol, glycol ether solvents, and combinations thereof. Suitableglycol ether solvents include, but are not limited to, diethylene glycolmethyl ether, dipropylene glycol methyl ether, 2-butoxy ethanol, ethersof a C₂ to C₆ dihydric alkanol containing at least one C₁ to C₆ alkylgroup, mono ethers of dihydric alkanols, methoxypropanol, butoxyethanol,hexoxyethanol, and isomers thereof. Selection of an appropriate solventis dependent on the resin composition chosen and is within the abilityof one skilled in the art, with the benefit of this disclosure.Generally, the selected solvent is added to the treatment fluid untilthe treatment fluid has a lower, desired viscosity. In particularembodiments, the treatment fluid may have viscosity of about 5 to about30 cP.

In addition to being used to introduce single fluids into a subterraneanformation, particular embodiments of the present invention may also beused to introduce multiple fluids, in succession, into a subterraneanformation. In accordance with the present invention, each fluid in thetreatment may be injected in the formation at a flow rate tailored toviscosity of the individual fluid being injected, such that the downhole pressure is maximized for each fluid as it is injected. In additionto enhancing the coverage and displacement of the individual fluids atthe time, such an injection technique may also enhance the coverageand/or displacement efficiency of the previously injected fluids,helping treat longer intervals of the well bore more effectively. Suchtailoring of injection rate may be particularly useful in operationswherein placement of the treatment fluid is preceded by a preflush fluidand/or followed by the placement of an afterflush fluid.

Preflush fluids suitable for use in the methods of the present inventioncomprise an aqueous liquid, a surfactant, and an optional mutualsolvent. The preflush solution, among other things, readies theformation to receive the integrated consolidation fluid and removes oilsthat may impede the integrated consolidation fluid from making contactwith the formation particles. Suitable aqueous liquids that may be usedto form the preflush fluid include, but are not limited to, fresh water,salt water, brine, combinations thereof, or any other aqueous liquidthat does not adversely react with the other components used inaccordance with this invention. When used, the mutual solvent should besoluble in both oil and water and be capable, among other things, ofremoving hydrocarbons deposited on particulates. Examples of suitablemutual solvents include, but are not limited to, glycol ethers. Somesuitable glycol ethers include ethyleneglycolmonobutyl ether, diethyleneglycol monomethyl ether, diethylene glycol dimethyl ether, dipropyleneglycol methyl ether, and combinations thereof. Any surfactant compatiblewith the aqueous liquid and capable of aiding the hardenable resin incoating the surface of unconsolidated particles of the subterraneanformation may be suitable for use in the present invention. Examples ofsurfactants suitable for use in the preflush fluids used in the methodsof the present invention include, but are not limited to, ethoxylatednonyl phenol phosphate esters, one or more cationic surfactants, one ormore nonionic surfactants, an alkyl phosphonate surfactant (e.g., aC₁₂-C₂₂ alkyl phosphonate surfactant), and mixtures thereof. Somesuitable mixtures of one or more cationic and nonionic surfactants aredescribed in U.S. Pat. No. 6,311,773 issued to Todd et al. on Nov. 6,2001, the disclosure of which is incorporated herein by reference.

The afterflush fluids suitable for use in the methods of the presentinvention comprise an aqueous liquid or an inert gas. Where theafterflush fluid is an aqueous liquid, it may be fresh water, saltwater, brine, or any other aqueous liquid that does not adversely reactwith the other components used in accordance with this invention. Wherean aqueous afterflush fluid is used, a volume of about 1 to about 5times the volume of the integrated consolidation fluid used is generallysuitable for use in the methods of the present invention. Moreover, insome subterranean formations, particularly gas-producing subterraneanformations, it may be advantageous to use afterflush fluids that areinert gases, such as nitrogen, rather than an aqueous solution. Suchafterflush fluids may prevent adverse interactions between theafterflush fluid and the formation. The afterflush fluid acts, interalia, to displace the curable resin from the well bore, to removecurable resin from the pore spaces inside the subterranean formationthereby restoring permeability, and to leave behind some resin at thecontact points between formation sand particulate to form a permeable,consolidated formation.

In some embodiments, the afterflush fluid further comprises asurfactant. When used, any surfactant compatible with the aqueous liquidand capable of aiding the hardenable resin in coating the surface ofunconsolidated particles of the subterranean formation may be suitablefor use in the present invention. Examples of surfactants suitable foruse in the afterflush fluids used in the methods of the presentinvention include, but are not limited to, ethoxylated nonyl phenolphosphate esters, one or more cationic surfactants, and one or morenonionic surfactants, and an alkyl phosphonate surfactant (e.g., aC₁₂-C₂₂ alkyl phosphonate surfactant). Mixtures of one or more cationicand nonionic surfactants are suitable and examples are described in U.S.Pat. No. 6,311,773 issued to Todd et al. on Nov. 6, 2001, the disclosureof which is incorporated herein by reference.

In some embodiments of the present invention a preflush fluid comprisinga water controlling agent may be placed into a portion of a subterraneanformation, followed by the placement of a resin treatment fluid,optionally followed by an afterflush fluid. In such embodiments,generally, at least one water controlling agent is included in thepreflush fluid in an amount sufficient to reduce the production of waterfrom the formation. In one embodiment, the water controlling agent isincluded in the preflush fluid in the range of from about 0.01% to about10% by weight of the preflush fluid. In another embodiment, the watercontrolling agent is included in the preflush fluid in the range of fromabout 0.1% to about 1% by weight of the preflush fluid.

To facilitate a better understanding of the present invention, thefollowing examples of preferred embodiments are given. In no way shouldthe following examples be read to limit or define the scope of theinvention.

Examples

A fluid placement simulation was performed to illustrate theeffectiveness of the method provided therein. The simulation involved awell bore having three intervals, having permeabilities of 5,000 mD,1,000 mD, and 500 mD, consecutively, and a reservoir pressure of 2,000psi at a depth of 5,000 ft. For simulation purpose, an interval lengthof 10 ft is assumed for each interval. Using a treatment fluid withviscosity of 1 cP, the treatment fluid was injected into the well at 2,4, 6, and 8 barrels per minute to determine the effect of injection rateon the penetration distance of the treatment fluid into the formation.It was found that most of the treatment fluid penetrates the 5,000-mDinterval, and only a small amount of treatment fluid enters the lowerpermeability intervals. Even as the injection rate was increased to ahigher rate, the penetration depth of treatment fluid into the 500 mDinterval was increased just a little.

Depth of Penetration (inches) of 1-cP Fluid Permeability of Interval at8 barrel/min Injection Rate 5,000 mD 10 1,000 mD 3   500 mD 1

As the viscosity of the fluid was increased to 7 cP, a dramaticimprovement in the penetration of treatment fluid into all intervals wasobserved, especially at high injection rate. It was observed that thedepth of penetration of treatment fluid into the low permeabilityintervals of 1,000 mD and 500 mD increased significantly. The increasein viscosity of treatment fluid provides resistance to penetration ofthe fluid into the high permeability interval, allowing the fluid todivert and penetrate into the lower-permeability intervals.

Depth of Penetration (inches) of 7-cP Fluid Permeability of Interval at8 barrel/min Injection Rate 5,000 mD 14 1,000 mD 8   500 mD 7

Therefore, the present invention is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Whilenumerous changes may be made by those skilled in the art, such changesare encompassed within the spirit of this invention as defined by theappended claims.

1. A method of injecting a treatment fluid into a portion of asubterranean formation having a wellbore therein, comprising: providinga treatment fluid having a viscosity; determining the breakdown pressureof the portion of the subterranean formation; mathematically calculatinga maximum sustainable flow rate for the treatment fluid based on: thedetermined breakdown pressure; the average pressure and permeability ofthe portion of the subterranean formation; the treatment fluidviscosity; the net pay; the radius of the formation cylinder in whichthe majority of the pressure drop takes place; and the radius and skinfactor of the wellbore; and, injecting the treatment fluid into theportion of the subterranean formation at a flow rate less than or equalto the maximum sustainable flow rate for the treatment fluid.
 2. Themethod of claim 1 wherein the treatment fluid comprises a watercontrolling agent.
 3. The method of claim 2 wherein the watercontrolling agent comprises a surfactant formed of one or more fattyacid imidazolyl compounds, a water-resistant polymer, or a combinationthereof.
 4. The method of claim 1 wherein the treatment fluid comprisesa curable resin.
 5. The method of claim 4 wherein the resin comprises atwo component epoxy based resin, a novolak resin, a polyepoxide resin, aphenol-aldehyde resin, a urea aldehyde resin, a urethane resin, aphenolic resin, a furan resin, a furan/furfuryl alcohol resin, aphenolic/latex resin, a phenol formaldehyde resin, a polyester resin, ahybrid polyester resin, a copolymer polyester resin, a polyurethaneresin, a hybrid polyurethane resin, a copolymer polyurethane resin, anacrylate resin, or a combination thereof.
 6. The method of claim 5wherein the treatment fluid further comprises an internal catalyst oractivator.
 7. The method of claim 4 wherein the treatment fluidcomprises a solvent.
 8. The method of claim 1 wherein the viscosity ofthe treatment fluid is from about 5 to about 30 cP.
 9. The method ofclaim 1 wherein the flow rate at which the treatment fluid is injectedinto the portion of the subterranean formation is less than or equal toabout 90% of the maximum sustainable flow rate.
 10. The method of claim1 wherein the flow rate at which the treatment fluid is injected intothe portion of the subterranean formation is less than or equal to about80% of the maximum sustainable flow rate.
 11. The method of claim 1wherein the portion of the subterranean formation comprises a pluralityof areas having distinct permeabilities.
 12. The method of claim 1further comprising the steps of: providing a preflush fluid having aviscosity; calculating a maximum sustainable flow rate for the preflushfluid, knowing the viscosity of the preflush fluid at which the preflushfluid can be injected without causing the portion of the subterraneanformation to breakdown; and, before the step of injecting the treatmentfluid into the portion of the subterranean formation, injecting thepreflush fluid into the portion of the subterranean formation at a flowrate less than or equal to the maximum sustainable flow rate for thepreflush fluid.
 13. The method of claim 12 wherein the preflush fluidcomprises an aqueous liquid and a surfactant.
 14. The method of claim 13wherein the preflush fluid further comprises a mutual solvent.
 15. Themethod of claim 12 further comprising the steps of: providing anafterflush fluid having a viscosity; calculating a maximum sustainableflow rate for the afterflush fluid; and, after the step of injecting thetreatment fluid into the portion of the subterranean formation,injecting the afterflush fluid into the portion of the subterraneanformation at a flow rate less than or equal to the maximum sustainableflow rate for the afterflush fluid.
 16. The method of claim 15 whereinthe afterflush fluid comprises an aqueous liquid and a surfactant. 17.The method of claim 16 wherein the surfactant comprises an ethoxylatednonyl phenol phosphate ester, a cationic surfactant, a nonionicsurfactant, an alkyl phosphonate surfactant, or a combination thereof.18. The method of claim 1 further comprising the steps of: providing anafterflush fluid having a viscosity; calculating a maximum sustainableflow rate for the afterflush fluid; and, after the step of injecting thetreatment fluid into the portion of the subterranean formation,injecting the afterflush fluid into the portion of the subterraneanformation at a flow rate less than or equal to the maximum sustainableflow rate for the afterflush fluid.
 19. The method of claim 18 whereinthe afterflush fluid comprises an aqueous liquid and a surfactant. 20.The method of claim 19 wherein the surfactant comprises an ethoxylatednonyl phenol phosphate ester, a cationic surfactant, a nonionicsurfactant, an alkyl phosphonate surfactant, or a combination thereof.